Swell-based inflation packer

ABSTRACT

An isolation packer. The packer is both an inflation packer and swell-based. That is, an outer shell or bladder may be utilized in conjunction with internal swell material. In advance of inflation, a void or cavity may be disposed between the inner surface of the shell and an outer surface of the swell material. Thus, fluid inflation of this void may result in an inflation that becomes swell-material filled until the void is eliminated leaving behind a more unitary and swollen packer of enhanced reliability.

FIELD

Embodiments described relate to inflation packers for use in downhole isolation. In particular, inflation packers are disclosed which are configured with a conventional or non-conventional shell equipped to accommodate novel media for inflation. More specifically, emerging downhole swell-based materials may be accommodated by the shell in a manner that provides synergistically improved seal capacity to the packer.

BACKGROUND

Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming, and ultimately very expensive endeavors. As a result, over the years, a significant amount of added emphasis has been placed on well monitoring and maintenance. Once more, perhaps even more emphasis has been directed at initial well architecture and design. All in all, careful attention to design, monitoring and maintenance may help maximize production and extend well life. Thus, a substantial return on the investment in the completed well may be better ensured.

In the case of well monitoring and logging, mostly minimally-invasive applications may be utilized which provide temperature, pressure and other production related information. By contrast, well design, completion and subsequent maintenance, may involve a host of more direct interventional applications. For example, perforations may be induced in the wall of the well, debris or tools and equipment removed, etc. In some cases, the well may even be designed or modified such that entire downhole regions are isolated or closed off from production. Such is often the case where an otherwise productive well region is prone to produce water or other undesirable fluid that tends to hamper hydrocarbon recovery.

Closing off well regions as noted above is generally achieved by way of setting one or more inflatable packers. Such packers may be set at downhole locations and serve to seal off certain downhole regions from other productive regions. Delivering, deploying and setting packers for isolation may be achieved by way of coiled tubing, or other conventional line delivery application. Alternatively, isolation may be pre-determined, for example, where packers are secured at set positions about a tubular in advance of its installation in the well. Regardless, subsequent packer deployment or inflation may be fairly sophisticated, given the amount of precision involved. For example, proper packer inflation may be quite challenging, given the high and variable temperature and pressure extremes often present downhole which can affect fluid inflation.

At present, packer inflation is achieved in a single shot, one-way manner. For example, a rupture disk and piston assembly may be utilized in conjunction with a one-way check valve for inflation of the packer to a predetermined pressure. That is, the packer assembly may be exposed to sufficient pressure for rupturing of the disk in a manner that triggers piston based fluid inflation of the packer to the predetermined amount. At such time the valve may be permanently turned off to hold the packer in a sealingly inflated state in the well.

Unfortunately, over time, the inflated packer is unlikely to remain in sealing engagement with the well wall. That is, due to natural leakage, downhole pressure or temperature changes, or even dehydration at the packer well wall interface, a conventional inflation packer is unlikely to maintain a seal beyond about 5-7 years or so. This is problematic given that the intended life of the well is more likely in the range of more than twenty years.

A variety of measures may be undertaken in order to address inflation packer failure during the life of the well. For example, direct intervention in the form of re-inflation may be attempted. However, given standard packer configurations follow-on placement and deployment of a new packer is generally a more viable alternative. Further, in some circumstances a cementing intervention may be attempted whereby cement is deposited at the location of the failing packer in hopes of reintroducing a seal at the location.

Unfortunately, all of the above-noted measures come with considerable drawbacks. Namely, a significant amount of time and expense is required to shut down operations, rig and re-rig equipment at the oilfield surface, and run an intervention. Once more, regardless of the particular remedial intervention attempted, restoration of completely functional seal to its original form is unlikely.

As an alternative to inflation packers, swell packers may be utilized. So, for example, issues associated with packer deflation may be avoided. Unfortunately, however, such packers are nevertheless subject to degradation over time in the face of harsh downhole conditions. So, for example, it remains unlikely that such packers would remain effective for say, an intended twenty year well life. As a result, operators are likely left with the option of costly follow-on remedial interventions or ultimately foregoing reliable isolation whether inflation packer or swell packers are utilized.

SUMMARY

A downhole isolation packer is detailed. The packer includes a shell configured for placement about a tubular for downhole use. A swellable material is located within a cavity of the shell. Further, the packer is configured with an inner fluid void taking up space in the cavity between an inner surface of the shell and an outer surface of the swellable material.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a cross-sectional view of an embodiment of an uninflated swell-based inflation packer taken from 1-1 of FIG. 2.

FIG. 1B is a cross-sectional view of a prior art embodiment of a conventional inflation packer.

FIG. 1C is a cross-sectional view of a prior art embodiment of a conventional swell packer.

FIG. 2 is a sectional side view of the swell-based inflation packer of FIG. 1A in an inflated state disposed in a well for isolation.

FIG. 3 is an overview of an oilfield revealing the well of FIG. 2 with the deployed swell-based inflation packer disposed therein.

FIG. 4A is a schematic side view of the swell-based inflation packer in an uninflated state.

FIG. 4B is a schematic side view of the swell-based inflation packer with an inflated inner fluid void.

FIG. 4C is a schematic side view of the swell-based inflation packer with swell material inflating into the void.

FIG. 4D is a schematic side view of the swell-based inflation packer with swell material inflating to reach an outer shell of the packer and eliminate the void.

FIG. 5 is a sectional side view of an alternate embodiment of an uninflated swell-based inflation packer disposed in a well and having a swell-based shell.

FIG. 6 is a flow-chart summarizing an embodiment of deploying and utilizing a swell-based inflation packer downhole in a well.

DETAILED DESCRIPTION

Embodiments herein are described with reference to certain types of downhole packers. For example, these embodiments focus on the use of packers for isolating certain downhole regions in conjunction with the use of production tubing. However, a variety of alternative applications may employ such swell-based packers, such as for well stimulation, completions, gravel packing, or isolation for water injection. Additionally, alternative packer-like devices, such as plugs, chokes, flow control valves and restrictors may take advantage of materials and techniques disclosed herein for use in a well or any other suitable conduit. Regardless, embodiments of packers disclosed herein are configured for inflation in a manner that incorporates an internal swell-based material.

Referring now to FIG. 1A, a cross-sectional view of a swell-based inflation packer 100 is shown. The cross-sectional view is taken from 1-1 of FIG. 2 where the packer 100 is depicted within a well 380 in an inflated state. For sake of illustration, the packer 100 is shown in an uninflated state in FIG. 1A (and the noted inflated state in FIG. 2). Regardless, the packer 100 includes an outer shell 110 serving as a bladder disposed about an inner fluid void 120 and swell material 130. In the embodiment shown, the packer 100 itself is disposed about a mandrel in the form of a tubular 160. More specifically, production tubing defining an inner channel 115 for hydrocarbon recovery is depicted. Although other forms of tubulars and mandrels for different types of applications may make use of a packer 100 as detailed herein.

The above noted swell material 130 may include any number of polymer particle types and configurations as are often employed in conventional swell packers and as detailed further below. Additionally, the shell 110 may also be of a traditional non-swell polymeric material such as a conventional non-reactive rubber as is often employed in conventional inflation packers. However, in one embodiment the shell 510 may also be made up of swellable polymer (see FIG. 5). Further, the fluid void 120 may be of negligible volume in advance of inflation as detailed below. Regardless, upon inflation and swelling, the packer 100 is configured to achieve an enhanced fluid isolating seal at the inner wall 187 of the casing 185. As depicted in FIG. 2, this seal is achieved in a manner substantially eliminating the void 120 as well as deflation and/or degradation issues often found in conventional packers.

By way of comparison to the swell-based inflation packer 100 of FIG. 1A, cross-sectional views of more conventional prior art packers 101, 102 are depicted in FIGS. 1B and 1C. More specifically, FIG. 1B reveals an embodiment of a prior art inflation packer 101 and FIG. 1C reveals a prior art swell packer 102. In both cases, the packers are shown deployed for isolation after a significant period of use, perhaps more than about 5-7 years downhole.

With specific reference to FIG. 1B, the exclusively bladder-type inflation packer 101 is subject to natural deflation over a period of use. That is, a single shot, one way nature of rupture disk/check valve inflation is generally employed for an inflation packer 101. Thus, it is left susceptible to deflation over a period, whether naturally through its polymeric bladder material, valve leakage, or as well pressures change. Whatever the case, unsealed openings 150, 155 are prone to develop adjacent the casing 187 or tubular 161 walls. This differs from embodiments of the swell-based packer 100 of FIG. 1A which is not reliant on pressure based inflation in order to maintain the seal and avoid such openings.

With specific reference to FIG. 1C, a swell packer 102 of swell material is depicted after a period of use, subject to natural degradation and cracking 157. That is, the packer 102 achieves a seal with the casing 185 after an initial swell period in which it is exposed to the downhole environment. However, over time, long after an adequate seal is achieved, the packer 102 remains exposed to the downhole environment and its naturally harsh conditions. As a result, the depicted cracking 157 and degradation may ensue, leaving the packer 102 prone to failure. Again, this differs from embodiments of the swell-based packer 100 of FIG. 1A which substantially avoids exposure of its swell material 130 to the downhole environment due to the presence of its more durable outer shell 110.

Continuing now with reference to FIG. 2, a sectional side view of the swell-based inflation packer 100 of FIG. 1A is depicted in an inflated state, following a significant period of use. Nevertheless, the swell of the swell material 130 has fully displaced the fluid of the void 120 depicted in FIG. 1A in such a manner that an isolated, near-solid polymeric mass remains isolated within the protection of the outer shell 110. Thus, with the swell eliminating deflation concerns and the shell 110 protecting the swell material 130, the integrity of the packer 100 and its seal remain intact.

The swell-based inflation of the packer as depicted in FIG. 2 may be achieved in a conventional manner. For example, an inflation tool 375 may be provided in conjunction with the packer 100. The tool 375 may include a conventional rupture disk and valve mechanism such as a one-way check valve or a flapper valve. Regardless, rupture of the disk and inflation may proceed in a manner delivering a predetermined amount of fluid to the void 120, as determined by pressure (see FIG. 1A). Further, in one embodiment, control over such inflation may be regulated over a line 200 equipped to deliver data and/or hydraulics from oilfield surface equipment 360 (see FIG. 3). Such inflation is detailed further with reference to the schematics of FIGS. 4A-4D hereinbelow.

Continuing with reference to FIG. 2, the swell material 130 may take an initial form of bead, pellet, powder or other suitable form tailored for its degree of interaction with inflation fluid. Additionally, solid bands or rings of the material 130 may be disposed about the tubular 160 to provide a degree of structural rigidity. As for the inflation fluid itself, water, perhaps mixed with constituents tailored to enhance the inflation may be utilized.

A variety of options are available for the swell material 130 such as polymers drawn from a betaine group prepared by inverse emulsion polymerization. Additional fillers, vulcanizing agents and other substances may be incorporated into the material 130 along with particular concentrations of cations and/or anions grafted thereto so as to tailor the sensitivity of the swell. From a structural standpoint, non-elastomeric polymers, fillers, plasticizers, and various fibers may also be incorporated into the swell material 130.

Referring now to FIG. 3, an overview of an oilfield 300 is depicted with the well 380 of FIG. 2 accommodating the swell-based inflation packer 100 of FIG. 1A therein. More specifically, in the embodiment shown, the well 380 and casing 185 are shown traversing various formation layers 390, 395. Indeed, the lower formation layer 395 may accommodate a production region 385 with a variety of perforations 387 to enhance hydrocarbon recovery therefrom. Alternatively, the upper formation layer 390 may be unproductive, water producing or otherwise sought to be isolated from recovery. Thus, the swell-based inflation packer 100 may be utilized as a measure of providing added isolation of the intake for the production tubing 160 from the upper formation layer 390. As such, recovery will be limited to fluids from below the packer 100, preferably from the production region 385 in particular. Even more notably, such recovery may be enhanced over time due to the reliability of the isolation provided by the packer 100 which is less susceptible to deflation, cracking or other age-based failures.

Continuing with reference to FIG. 3, deployment of the packer 100 for such isolation may be initiated by the inflation tool 375 as described above. This may involve fluid inflation followed by a swell period for a length of time determined based on the particular swell material 130 selected (see FIG. 2). As also, noted above, this inflation may be initiated by surface equipment 360 disposed at the oilfield surface 300. More specifically, a control unit 365 for directing packer deployment and other downhole applications may be disposed adjacent the well head 350 (along with a line 355 for transporting recovery fluids). Indeed, a rig 370 may be disposed over the well 380 for supporting a host of additional surface equipment for a variety of different downhole applications.

Referring now to FIGS. 4A-4D, schematic representations of the swell-based inflation packer 100 over the course of an inflation application are depicted. More specifically, FIG. 4A is a schematic side view of the packer 100 in an uninflated state. FIG. 4B is a schematic side view of the packer 100 with an inflated inner fluid void 120 whereas FIG. 4C reveals the more internal swell material 130 inflating into the void 120. Lastly, FIG. 4D is a view of the packer 100 with the internal swell material 130 reaching a full swell and contacting the outer shell 110 in a manner substantially eliminating the void 120.

With specific reference to FIGS. 4A and 4B, the packer 100 goes from the uniflated profile of FIG. 4A to the inflated profile of FIG. 4B in relatively short order. That is, as alluded to above, the inner fluid void 120 may be rapidly inflated as directed by surface equipment 360, perhaps through use of an inflation tool 375 (see FIG. 3). The particular fluid utilized for the inflation may be water-based as indicated above, oil-based, diesel-based, or a wellbore or other suitable inflation fluid.

With specific reference to FIGS. 4C and 4D, the inflated packer 100 may undergo the above-noted swell period as the swollen void 120 is overtaken by the swell material 130. That is, for a period, the swell material 130 will absorb, adsorb or otherwise soak up the fluid volume of the void 120 until it makes substantially uniform contact with, and is restrained and protected by the inner surface of the outer shell 110. All in all, this may take from many hours to perhaps days or even months depending on the particular swell material 130 selected.

Referring now to FIG. 5, a sectional side view of an alternate embodiment of an uninflated swell-based inflation packer 500 is shown disposed in the well 380. In this embodiment, the material of the outer shell 510 is now swell-based. That is, as opposed to, for example, a conventional non-reactive rubber, the shell 510 may be constructed of a swellable polymer. Thus, the swell period noted above may be substantially reduced. That is to say, the time it takes for substantial elimination of the fluid void 120 by fluid uptake may be reduced. This is because, the void 120 is now defined substantially entirely by swell-based material (i.e. that of both the inner swell material 130 and the shell 120). Such an embodiment may be of particular advantage where rapidly achieving a completed swell is of greater import than, for example, an extended downhole packer life.

In the embodiment of FIG. 5, an added degree of rapidity may also be found in terms of the swell of the shell 510 in particular. This would be the case where the shell 510 is constructed of a material swellable upon exposure to fluids likely present downhole (ie. wellbore type fluids). That is, where the outer surface of the shell 510 would be exposed to such fluids already in the well 380 and the inner surface of the shell 510 is exposed to such fluids via inflation as noted above.

Referring now to FIG. 6, a flow-chart summarizing an embodiment of deploying and utilizing a swell-based inflation packer in a well is depicted. Indeed an embodiment of a swell-packer as detailed hereinabove may be delivered to a target location in a well by conventional means as indicated at 615. The packer may then be inflated as noted at 635 by inflation with an inflation fluid that is reactive with a swell material within the packer. Indeed, as indicated at 655, an interior swell material may be swollen by the fluid.

Swelling of the swell material within the packer may take place until the material cohesively reaches an outer shell of the packer, thereby sealably isolating the target location with a structurally uniform inflated and swollen packer (see 695). Furthermore, achieving this type of isolation may be further aided by use of a shell which is also constructed of swell material as noted at 675.

Embodiments described hereinabove provide a manner by which packer reliability may be substantially enhanced, thereby extending useful packer life as well. Thus, the amount of time and expense dedicated to remedial interventions and/or packer replacements for conventional inflation or swell packers may be kept to a minimum. Further, in some cases, the combination of inflation and swell-based materials may also be utilized to speed up inflation.

The preceding description has been presented with reference to presently preferred embodiments. Persons skilled in the art and technology to which these embodiments pertain will appreciate that alterations and changes in the described structures and methods of operation may be practiced without meaningfully departing from the principle, and scope of these embodiments. For example, whereas the inflated and swollen device detailed herein is provided in the form of a packer for downhole isolation, other types of devices for alternative applications may be involved. Along these lines, such devices may be directed at marine applications, or water and sewage line repairs. Furthermore, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope. 

1. A downhole isolation device for placement in a well, the device comprising: a shell for disposing about a downhole mandrel; and a swellable material disposed within a cavity of said shell, the device having an inner fluid void between an inner surface of said shell and an outer surface of said material.
 2. The device of claim 1 wherein said shell is of a non-swell polymeric material.
 3. The device of claim 2 wherein said shell material is a non-reactive rubber.
 4. The device of claim 1 wherein said shell is configured to protect said swellable material from exposure to downhole exposure.
 5. The device of claim 1 wherein said swellable material is of one of bead, pellet and powder form.
 6. The device of claim 1 wherein said swellable material includes at least one solid band thereof about the mandrel.
 7. The device of claim 1 wherein said shell is of a swellable polymer to reduce a swell period of the device.
 8. The device of claim 7 wherein the swellable polymer is swellable upon exposure to a wellbore type fluid.
 9. A downhole isolation packer comprising: a shell for disposing about a downhole tubular; and a swellable material disposed within a cavity of said shell, the packer having an inner fluid void between an inner surface of said shell and an outer surface of said material.
 10. The packer of claim 9 wherein said tubular is production tubing.
 11. A method of providing fluid isolation at a target location of a conduit, the method comprising: delivering a swell-based inflation device to the target location; inflating a fluid void of the device with an inflation fluid; swelling an interior swell material of the device with the fluid to achieve the isolation.
 12. The method of claim 11 wherein the fluid isolation is employed in one of a downhole wellbore application, a marine application, water line repair and sewage line repair.
 13. The method of claim 12 wherein the downhole wellbore application comprises utilizing one of a water-based fluid, an oil-based fluid, a diesel fluid, and a wellbore type fluid as the inflation fluid for said inflating.
 14. The method of claim 12 wherein the downhole wellbore application is configured to provide a substantially effective seal in a wellbore for a period exceeding about 7 years.
 15. The method of claim 11 wherein said inflating comprises supplying a predetermined amount of the inflation fluid to the void in a one-way manner.
 16. The method of claim 15 wherein the predetermined amount of the inflation fluid is pressure determined.
 17. The method of claim 11 wherein said swelling takes place over the course of a swell period as the swell material takes up the inflation fluid.
 18. The method of claim 17 wherein a duration of the swell period is tailored based on the types of swell material and inflation fluid employed.
 19. A method of providing fluid isolation at a target location in a wellbore of a well, the method comprising: delivering a swell-based inflation packer to the target location; inflating a fluid void of the packer with an inflation fluid; swelling an interior swell material of the device with the fluid; and swelling a shell of the packer exterior the swell material with the fluid to reduce a swell period of the packer.
 20. The method of claim 19 wherein the fluid is a wellbore type fluid and the shell is swellable upon exposure thereto at a surface within the packer and at an opposite surface exposed to the wellbore. 